This invention relates to a surfactant flooding system for recovering heavy oil. More particularly, the invention concerns a surfactant system containing an alkoxylated surfactant which is water soluble at ambient temperature but has a large enough hydrophobe to be oil soluble at a reservoir temperature above its cloud point.
Surfactant flooding demands careful planning of the composition, concentration and salinity of the surfactant slug. Because the surfactant slugs must interact with the reservoir crude at reservoir conditions, a surfactant system is designed to have the lowest interfacial tension between water and oil at reservoir conditions. It is well-known in the art that the lowest interfacial tension possible with a surfactant system (and the best oil recovery) will occur if the surfactant system is designed to form a microemulsion with the reservoir crude at or near the mid-phase region of a three phase system called a Type III phase environment or regime.
An emulsion is a phase suspended in another immiscible phase, which may or may not be thermodynamic equilibrim. A microemulsion is a thermodynacically stable emulsion.
Microemulsions are generally classified as oil-in-water microemulsions, water-in-oil microemulsions, and middle phase microemulsions. An oil-in-water microemulsion is a microemulsion in which the external or continuous phase is water and the dispersed phase is oil. A surfactant-water mixture which forms an oil-in-water microemulsion can equilibrate as a single phase or as two phases such as a lower phase oil-in-water microemulsion plus an equilibrium upper phase of oil, depending on the overall composition of the mixture. Such mixtures are defined by those skilled in the art of surfactant flooding as existing in a Type II(-) phase environment.
A water-in-oil microemulsion is an microemulsion in which the external or continuous phase is oil and the dispersed phase is water. A surfactant-oil-water mixture which forms a water-in-oil microemulsion can equilibrate as a single phase or as two phases of an upper phase water-in-oil microemulsion plus an equilibrium lower phase of excess water depending on the overall composition of the mixture. Such mixtures are defined by those skilled in the art of surfactant flooding as existing a Type II(+) phase environment.
A middle phase microemulsion is an microemulsion in which there is apparently no identifiable external or continuous phase. A surfactant-oil-water mixture which forms a middle phase microemulsion can equilibrate as a single phase, as two phases of a middle phase microemulsion plus an equilibrium phase or excess oil or excess water, or as three phases. The three phases would be a middle phase microemulsion plus an equilibrium water phase and an equilibrium oil phase. The end result of the equilibrated microemulsion depends on the overall composition of the mixture. Such mixtures are defined by those skilled in the art of surfactant flooding as existing in Type III phase environments or regimes. It should be emphasized that the best oil recovery from surfactant flooding generally occurs when the surfactant slug and reservoir oil form a middle phase microemulsion in a Type III phase environment. This is the goal of surfactant system planning.
Heavy viscous oils present significant problems in the design of surfactant assisted floods. These problems are aggravated by the fact that most heavy oil fields in North America that are surfactant flood candidates have been steamflooded. Steamflooding insures that reservoir salinity will be very low, frequently of a lower salinity than most municipal water systems. This low salinity combined with the heavy oil makes it difficult to design a surfactant system which will form an microemulsion with the oil in the Type III regime where some oil and brine is solubilized in the mid-phase.
It is useful to describe two characteristics of surfactant phase behavior. At a fixed oil weight, temperature and surfactant composition, as salinity increases the phase regime changes from a Type II(-) where the surfactant is in water to a Type III where the surfactant is in the desirable mid-phase to a Type II(+) where the surfactant and some brine has moved into the oil phase. Consequently, in the low salinity environments of most heavy oil fields, particularly if they have been steamflooded, it is difficult to get out of a Type II(-) phase regime where the surfactant is in water to a Type III mid-phase.
A second characteristic of surfactant systems defines the role of oil in phase behavior. At a fixed salinity and surfactant composition, as the oil weight increases to a heavier crude with a higher equivalent alkane carbon number (EACN), the surfactant will move through the phase regimes in the opposite direction as increasing salinity. For a low EACN the mixture of surfactant, oil and water will be in a Type II(+) phase regime where the surfactant resides in the oil phase. As the EACN increases, the system will go through the mid-phase region of the Type III on its way to a Type II(-) phase regime with the surfactant in water for a high EACN or viscous oil.
Because of the two above relationships with increasing salinity and increasing oil weight, it is doubly difficult to design a surfactant system that will emulsify with the reservoir crude in the mid-phase of a Type III environment. The heavy weight of the reservoir crude will tend to exhibit Type II(-) phase behavior. The low salinity of such reservoirs also tends to force any resulting microemulsion of the surfactant, water and oil to be in a Type II(-) phase environment. In both cases, there is strong pressure forcing the surfactant into the water, making it difficult to solubilize the oil.
A third factor working against surfactant flooding of steamflooded reservoirs is the relatively high reservoir temperature. As the temperature of the reservoir increases, ionic surfactants become more water soluble and alkyoxylated nonionics become more oil soluble. Thus, high salt concentrations are required to attain the mid-phase with its minimum interfacial tension. For alkyl and alkylaryl surfactants, this effect of temperature on interfacial tension is small but indicative of increasing surfactant solubility in water with increasing temperature. The low salinity brine of steamflooded reservoirs, however, runs counter to the extra salinity needed at higher temperatures.
Another complicating factor in the surfactant flooding of heavy oil reservoirs is that it is more difficult to solubilize a heavy viscous oil than it is to emulsify a light oil. For heavy oil with a high EACN, a surfactant is required with a large hydrophobe. Most surfactants with large hydrophobes are not water soluble. As a result, another difficulty arises in solubilizing the surfactant or multiple surfactants in an aqueous solution for initial injection. There will almost always be injection problems associated with a system that is oil soluble but not water soluble.
It is for these reasons that surfactant flooding of heavy oil reservoirs, particularly those that have been steamflooded, is virtually unknown in the art. Some discussion of these issues can be found in Ziegler, V. M., "Laboratory Investigation of High Temperature Surfactant Flooding," Society of Petroleum Engineers Journal, May 1988, pp. 587-596. Unfortunately, the reference offered no acceptable solution in its discussion of the possible flooding of heavy oil from a Kern River reservoir which had been steamflooded. Ziegler had two answers. First, he used a 10% saline preflush for every test. This high salinity was needed to force the surfactant to be more oil soluble. Second, he dropped the salinity of his surfactant slugs to facilitate handling and injection, but this sacrificed optimum surfactant performance. The dual use of the high brine preflush and brine with the surfactant slug would be adequate in a reservoir.